Method and apparatus using coiled-in-coiled tubing

ABSTRACT

Method and apparatus for performing well operations, such as measuring or forming or testing or treating or the like, and combinations of the above operations, including the use of coiled-in-coiled tubing (CCT) connected to a bottomhole assembly package (BHA), such that the assembly is in communication with both fluid conduits (80 and 82) defined by the coiled-in-coiled tubing.

This is a Continuation-in-Part of PCT US 95/10007, filed Jul. 25, 1995,also U.S. Ser. No. 08/564,355 filed Mar. 19, 1996 now U.S. Pat. No.5,638,904, allowed Dec. 12, 1996.

FIELD OF THE INVENTION

This invention pertains to safeguarded methods and apparatus forproviding fluid communication with coiled tubing, useful incommunicating fluids within wells, and particularly applicable to drillstem testing and/or operations in sour wells. The invention furtherpertains to multicentric coiled-in-coiled tubing, useful for safeguardeddownhole or conduit operations, and its method of assembly, includingpreferred and alternate methods. The invention also pertains to the useof coiled-in-coiled tubing with a bottomhole assembly package foroperations that may be particularly pertinent to horizontal and/ordeviated wells, including operations such as treating or forming ortesting or measuring and the like, and in particular, to combinations ofthe above operations performable in the same run.

BACKGROUND OF INVENTION

This application is related to and comprises a continuation in part ofprior pending application having PCT Serial Number PCT/US95/10007. Thecorresponding U.S. Ser. No. is 08/564/355.

The oil and gas industry uses various methods to test the productivityof wells prior to completing and tying a well into a pipeline orbattery. After drilling operations have been completed and a well hasbeen drilled to total depth (“TD”), or prior to reaching TD in the caseof multi-zoned discoveries, it is common to perform a drill stem test(“DST”). This test estimates future production of oil or gas and canjustify a further expenditure of capital to complete the well.

The decision to “case” a well to a particular depth, known as a “casingpoint election”, can result in an expenditure in excess of $300,000.Without a DST, a wellsite geologist must make a casing point electionbased on only core samples, cuttings, well logs, or other indicators ofpay thicknesses. In many cases reservoir factors that were not knowableat the time of first penetration of the producing zone, and thus notreflected in the samples, cuttings, etc., can control the ultimateproduction of a well. A wellsite geologist's problem is exacerbated ifthe well is exploratory, or a wildcat well, without the benefit ofcomparative adjacent well information. Further, the geologist must makea casing point election quickly as rig time is charged by the hour.

A DST comprises, thus, a valuable and commonly used method fordetermining the productivity of a well so that optimal information isavailable to the geologist to make a casing point election.Traditionally the DST process involves flowing a well through a lengthof drill pipe reinserted through the static drilling fluid. The bottomof the pipe will attach to a tool or device with openings through whichwell fluids can enter. This perforated section is placed across ananticipated producing formation and sealed off from the rest of thewellbore with packers, frequently a pair of packers placed both aboveand below the formation. The packer placement or packing off techniquepermits an operator to test only an isolated section or cumulativesections. The testing can involve actual production into surfacecontainers or containment of the production fluid in the closed chambercomprised by the pipe, pressure testing, physically retrieving samplesof well fluids from the formation level and/or other valuablemeasurements.

The native pressure in producing reservoirs is controlled duringdrilling through the use of a carefully weighted fluid, referred toabove and commonly called “drilling mud”. The “mud” is continuouslycirculated during the drilling to remove cuttings and to control thewell should a pressurized zone be encountered. The mud is usuallycirculated down the inside of the drill pipe and up the annulus outsideof the pipe and is typically made up using water or oil based liquid.The mud density is controlled through the use of various materials forthe purpose of maintaining a desired hydrostatic pressure, usually inexcess of the anticipated native reservoir pressure. Polymers and suchare typically added to the mud to intentionally create a “filter cake”sheath-like barrier along the wellbore surface in order to staunch lossof over-pressured drilling fluid out into the formation.

As can be easily appreciated, when an upper packer of a DST tool sealsan annular area between a test string and a borehole wall, thehydrostatic pressure from the column of drilling fluid is relieved onthe wellbore below the packer. The well below the packer, thus, can flowif an open fluid communication channel exists to the surface. At leastthe well will flow to the extent that native pressure present at theopen formation of the isolated section exceeds the hydrostatic headpressure of the tested fluids in the drill pipe. Such produced fluidsthat flow to or toward the surface are either trapped in the pipe stringor collected in a container of known dimensions and/or flared off. Bycalculating the volume of actual fluid produced, after considering suchfactors as the time of the test and the size of the choke used, areasonable estimate of the ultimate potential production capacity of awell can be made. Upon occasion formation pores are too clogged, as bythe drilling fluid filter cake, to be overcome by formation pressure andflow. It may be desired in such cases to deliver a gas or an acid to theformation to stimulate flow.

Many wells throughout the world contain hydrogen sulfide gas (H2S), alsoknown as “sour gas”. Hydrogen sulfide gas can be harmful to humans orlivestock at very low concentrations in the atmosphere. In Alberta,Canada, sour wells commonly produce hydrocarbon fluids withconcentrations of 2-4% H2S and often as high as 30-35% H2S. These areamong the most sour wells in the world. It is also known that sour gascan cause embrittlement of steel, such as the steel used in drill pipe.This is especially true when drill pipe contains hardened steel, whichis commonly used to increase the life of the drill string. Due to atendency for drill pipe to become embrittled when exposed to H2S and thepossibly disastrous effect of sour gas in the atmosphere with itspotential for environmental damage or injury to people or animals, it isextremely uncommon to perform drill stem tests on sour wells. Even a pinhole leak in a drill pipe used for such purposes could have deleteriousresults.

Unfortunately, many highly productive wells are very sour and found inexploratory areas. In some cases, oil companies have been prepared to goto the expense of temporarily completing a sour well by rentingproduction tubing and hanging it in a well without cementing casing inplace, just to effect a production test. This method, due to theincrease in rig time, can cost in excess of $200,000, which could begreater than the cost of a completion in shallow wells.

Coiled tubing is now known to be useful for a myriad of oilfieldexploration, testing and/or production related operations. The use ofcoiled tubing began more than two decades ago. In the years that havefollowed coiled tubing has evolved to meet exacting standards ofperformance and to become a reliable component in the oil and gasservice industry. Coiled tubing is typically manufactured from strips oflow alloy mild steel with a precision cut, and rolled and seam welded ina range of OD (outside diameter) sizes, envisioned to run up to 6inches. Currently, OD sizes are available up to approximately 4 inches.Improvements in manufacturing technology have resulted in increasedmaterial strength and consistent material quality. Development of a“strip bias weld” has improved the reliability of factory made joints inthe coiled tubing string. Heat treatment and material changes haveincreased resistance of the tubing to H2S induced embrittlement andstress corrosion cracking that can incur in operations in sourenvironments. An increase in wall thickness and the development ofhigher strength alloys are also allowing the industry to increase thedepth and pressure limits within which the tubing may be run. Theintroduction of new materials and structure, such as titanium andcomposite material tubing design, is also expected to further expandcoiled tubing's scope of work.

Coiled tubing could be particularly valuable in sour or very sour wellsdue to coiled tubing's typically softer steel composition that is not sosusceptible to hydrogen sulfide embrittlement. However, another factorinhibits producing sour gas or performing a DST in a sour well withcoiled tubing. The repeated coiling and uncoiling of coiled tubingcauses tubing walls, presently made of the steel, to plastically deform.Sooner or later the plastic deformation of the tubing wells is likely tocause a fracture. A resulting small pin hole leak or crack could produceemissions.

Oil and gas operations have known the use of concentric pipe strings.Concentric pipe strings provide two non wellbore channels for fluidcommunication downhole, typically with one channel, such as the innerchannel, used to pump fluid (liquid or gas or multiphase fluid) downholewhile a second channel, such as the annular channel formed between theconcentric strings, used to return fluid to the surface. (A furtherannulus created between the outer string and the casing or liner orwellbore could, of course, be used for further fluid communication).Which channel is used for which function can be a matter of designchoice. Both concentric pipe channels could be used to pump up or down.

Concentric tubing utilizing coiled tubing, at least in part, has beenproposed for use in some recent applications. Coiled tubing enjoyscertain inherent advantages over jointed pipe, such as greater speed inrunning in and out of a well, greater flexibility for running in “live”wells and greater safety due to requiring less personnel to be presentin high risk areas and the absence of joints and their inherent risk ofleaks.

Patterson in U.S. Pat. No. 4,744,420 teaches concentric tubing where theinner tubing member may be coiled tubing. It is inserted into an outertubing member after that member has been lowered into the wellbore. InPatterson the outer tubing member does not comprise coiled tubing. AsFIG. 8 of Patterson illustrates, the inner tubing is secured within theouter tubing by spaced apart spoke-like braces or centralizers whichhold the tubing members generally centered and coaxial. Sudol in U.S.Pat. No. 5,033,545 and Canadian Patent No. 1325969 discloses coaxiallyarranged endless inner and outer tubing strings. Sudol's coaxialcomposite can be stored on a truckable spool and run in or pulled out ofa well by a tubing injector. Sudol's disclosure does not explicitlydisclose how the coaxial tubing strings are maintained coaxial, butSudol does show an understanding of the use of centralizers. U.S. Pat.No. 5,086,8422 to Cholet discloses an external pipe column 16 which isinserted into a main pipe column comprising a vertical section and acurved section. An internal pipe column is then lowered into the insideof the external pipe column. Cholet teaches that the pipe columns may beformed to be the rigid tubes screwed together or of continuous elementsunwound from the surface. Cholet does not teach a single tubingcomposite that itself is wound on a spool, the composite itselfcomprising an inner tubing length and an outer tubing length. All ofCholet's drawings teach coaxial concentricity. U.S. Pat. No. 5,411,105to Gray teaches drilling with coiled tubing wherein an inner tubing isattached to the reel shaft and extended through the coiled tubing to thedrilling tool. Gas is supplied down the inner tube to permitunderbalanced drilling. Gray, like Sudol, discloses coaxial tubing.Further, Gray does not teach a size for the inner tube or whether theinner tube comprises coiled tubing. A natural assumption would be, inGray's operation, that the inner tube could comprise a small diameterflexible tube insertable by fluid into coiled tubing while on the spool,like wireline is presently inserted into coiled tubing while on thespool. The Griffiths patent, U.S. Pat. No. 5,503,014, issued Apr. 2,1996, filed Jul. 29, 1994, practices a version of drill stem testingusing dual coaxial coil. No test tool or bottomhole assembly is taught.

The present invention solves the problem of providing a safeguardedmethod for communicating potentially hazardous fluids and materialsthrough coiled tubing. This safeguarded method is particularlyapplicable for producing and testing fluids from wells including verysour gas wells. The safeguarded method proposes the use ofcoiled-in-coiled tubing, comprising an inside coiled tubing lengthlocated within an outside coiled tubing length. Potentially hazardousfluid or material is communicated through the inside tubing length. Theoutside tubing length provides a backup protective layer. The outsidetubing defines an annular region between the lengths that can bepressurized and/or monitored for a quick indication of any leak ineither of the tubing lengths. Upon detection of a leak, fluidcommunication can be stopped, a well could be killed or shut in, orother measures could be taken before a fluid impermissibly contaminatesits surroundings.

As an additional feature, the annular region between the tubing lengthscan be used for circulating fluid down and flushing up the insidetubing, for providing stimulating fluid to a formation, for providinglift fluid to the inside tubing or for providing fluid to inflatepackers located on an attached downhole device, etc.

The present invention also relates to the assembly of multicentriccoiled-in-coiled tubing, the proposed structure offering a configurationand a method of improved or novel design. This improved or novel designprovides advantages of efficient, effective assembly, longevity of useor enhanced longevity with use, and possibly enhanced structuralstrength. A preferred method and alternate methods of assembly ofmulticentric and concentric coil-in-coil are disclosed.

It has been discovered that coiled-in-coiled tubing can offer the samebenefits of flexibility and thrustability that are found in singlecoiled tubing when compared to jointed pipe, characteristicsparticularly useful for work in horizontal and/or deviated wells.However, coiled-in-coiled tubing provides the operator with two conduitsas opposed to one for the communication of fluids, as from the surfaceto the bottomhole, or from the bottomhole to the surface, from thesurface to tool combinations in a bottomhole assembly, and/or to providean insulating chamber. These conduits are in addition, of course, to thetubing-wellbore annulus that can or could be used as a conduit.

Some operations, as discussed above and below, can benefit from theavailability of a safeguarded or insulated production conduit. Sometools, as mentioned in the above discussion of Sudol and the sandvacuuming tool, prescribe two fluid conduits for their operation, andothers might benefit from such.

Given the construction of prototype coiled-in-coiled tubing, it has beensubsequently discovered that well operations such as treating, forming,testing and/or measuring operations and the like, and especiallyincluding combinations of the above, could be performed cost effectivelyon coil-in-coil. For instance, the efficiency of testing combined withwell enhancing operations could be increased if performed in the samerun downhole with other operations. The flexibility provided by theavailability of plural conduits for pumping down, pumping up, andcirculating fluids, and performing the same simultaneously orsequentially, makes possible many novel combinations of operations notbefore possible in a run downhole. Plural circulating conduits permitcombinations of operations to be performed downhole in new, improved andnovel manners. The added efficiency can justify the added cost ofutilizing coil-in-coil, as well as add a safety factor.

SUMMARY OF THE INVENTION

This invention relates to the use of coiled-in-coiled tubing (severalhundred feet of a smaller diameter inner coiled tube located within alarger diameter outer coiled tube) to provide a safeguarded method forfluid communication. The invention is particularly useful for wellproduction and testing. The apparatus and method are of particularpractical importance today for drill stem testing and other testing orproduction in potentially sour or very sour wells. The invention alsorelates to an improved “multicentric” coiled-in-coiled tubing design,and its method of assembly.

The use of two coiled tubing strings, one arranged inside the other,doubles the mechanical barriers to the outside environment. Fluid in theannulus between the strings can be monitored for leaks. To aidmonitoring, the annular region between the coils can be filled with aninert gas, such as nitrogen, or a fluid such as water, mud or acombination thereof, and pressurized.

In one embodiment a fluid, such as water or an inert gas, can be placedin the annulus between the tubings and pressurized. This annular fluidcan be pressurized to a greater pressure than either the pressure of thehazardous fluid being communicated via the innermost string or thepressure of the fluid surrounding the outer string, such as staticdrilling fluid. Because of this pressure differential, if a pin holeleak or a crack were to develop in either coiled tubing string the fluidin the annulus between the inner and outer string would flow outwardthrough the hole. Instead of sour gas, for instance, potentially leakingout and contaminating the environment, the inner string fluid would beinvaded by the annular fluid and continue to be contained in a closedsystem. An annular pressure gauge at the surface could be used toregister a pressure drop in annular fluid, indicating the presence of aleak.

Communicated fluids through the inner string could be left in the closedchamber comprised of the inner string, for one embodiment, or could beseparately channeled from the coiled-in-coiled tubing at the spool orworking reel. Separately channeled fluids could be measured, or fed intoa flare at the surface or produced into a closed container, for otherembodiments.

The coiled-in-coiled tubing should be coupled or attached to a device atits distal end to control fluids flowing through the inner tube. Fluidcommunications through the annular channel should also be controlled. Ata minimum this control might comprise simply sealing off the annularregion. For drill stem testing, packers and packing off techniques couldbe used in a similar fashion as with standard drill stem tests. Anadditional benefit is provided by the invention in that a downholepacker could be inflated with fluid supplied down the coiled-in-coiledtubing.

The inner coiled tube is envisioned to vary in size between ½″ (inches)and 5½″ (inches) in outside diameter (“OD”). The outer coiled tube canvary between 1″ and 6″ in outside diameter. A preferred size is 1¼ to1½″ O.D. for the inner tube and 2″ to 2⅜″ O.D. for the outer tube.

It is known that steel of a hardness of less than 22 on the Rockwell Chardness scale is suitable for sour gas uses. Coiled tubing can becommonly produced with a hardness of less than 22, being without theneed for the strength required for standard drill pipe. Thus, coiledtubing is particularly fit for sour gas uses, including drill stemtesting, as disclosed. Other materials such as titanium, corrosionresistant alloy (CRA) or fiber and resin composite could be used forcoiled tubing. Alternately, other metals or elements could be added tocoiled tubing during its fabrication to increase its life and/orusefulness.

The invention further includes apparatus and method for use in downholewell operations such as treating, forming, testing or measuring and thelike, and especially in combinations of the above. Treating operationsrefer generally to operations such as acidizing or fracturing or heatingor other well stimulating activities, including injecting chemical andbiological additives. Specifically, treating might refer to operationssuch as a polymer squeeze to close off suspected water producing zones,clay swelling control mechanisms, sand control mechanisms, filter cakeremoval systems, iron or sludge control and fines migration control.Treating might also refer to the addition of one or more of thefollowing, either separately or in combination: emulsifiers, gellants,polymers, surfactants, buffers, neutralizers, corrosion control agents,inhibitors, diverting agents, breakers, cements, fluid loss controladditives, detergents, cleaning agents, solvents, sequesterants,suspending agents, gels or proppants, foam or defoamers, gases, frictionreducers, retarders, lost circulation material, flushes and preflushes,wax or paraffin removers, asphaltine control agents, viscosifiers,dispersants, bonding agents, cement additives and scale inhibitors.Generally, treating fluids could refer to any combination of acid and/orfracturing fluids as well as to additives thereto. Treating fluids wouldbe mixed and applied simultaneously or sequentially according to theneed of the particular formation. Treating operations could include jetcleaning and sand vacuuming operations.

Forming operations include operations such as drilling, modifying,perfing (perforating), establishing build sections and forming dog legs,as well as other activities that affect the structure and conformance ofthe wellbore.

Testing operations include producing operations, including bothproduction testing and long term production. A general purpose toolmight be referred to as a production/test tool.

There could be an overlap between testing tools and measuring tools.Measuring tools include the spectrum of logging tools as well aspressure measuring devices, flow meters, densitometers, locating tools,sampling tools and tools to perform chemical analyses or geological andgeophysical analyses downhole.

Apparatus for use in well operations in accordance with the presentinvention comprises coiled-in-coiled tubing having an inner coiledtubing length contained within an outer coiled tubing length. The twotubing lengths define a first inner coil fluid conduit and a secondinter-coil “annular” fluid conduit. The apparatus includes a bottomholeassembly package adapted to attach to a portion of the coiled-in-coiledtubing, typically attaching to the distal end of the coiled-in-coiledtubing, and in fluid communication with both fluid conduits defined bythe coiled-in-coiled tubing.

The apparatus may include at least one packer adapted to be associatedwith the bottomhole assembly or the tubing. Typically the packer wouldbe associated with the bottomhole assembly and might comprise a straddlepacker. The packer optionally could be structured to permit the tubingto reciprocate or to slide while the packer packs off between a portionof the borehole wall and the tubing.

An emergency packer deflation mechanism might be included in the eventof loss of communication. The mechanism could operate by pressureapplication to a sheer pin or a number of pins or by a variety of othermethods, which would allow fluid to escape from the packers to thewellbore or to the coil tubing.

In most applications a surface control mechanism would control fluidcommunication within both the inner conduit and the coiled-in-coiledannular conduit. Preferably the coiled-in-coiled tubing at the surfacewould be connected to a spool or reel at its proximate end. The flowfrom both conduits could be separated with an adapting mechanism at thespool or reel to channel or control each flow separately, as desired.

A bottomhole assembly package could range from the elaborate to thesimple. A drillstem test tool as disclosed in FIGS. 5 and 5A compriseone bottomhole assembly package. The tool is designed such that it couldfunction as a production/test tool and a treatment injection tool.Valves in the tool control fluid communication between the inner and theannular conduits and the wellbore as well as between the conduitsthemselves. Alternately, a bottomhole assembly might comprise one ormore of a production/test tool, a pump tool, a treatment injection tool,a vacuum tool, a jetting tool, a perfing tool, a drilling tool, anorienting tool, a hydraulic motor and/or an electric motor. A treatmentinjecting tool could inject treatment fluid. The bottomhole assemblymight include a variable spacing unit. Such units could provide spacingfrom one to fifty meters.

Presently available tools, such as enumerated in the above list, wouldlikely need to be adapted to work effectively with coiled-in-coiledtubing in a bottomhole assembly package. Some tools, such as a Sudolsand vacuuming tool, or a drillstem test tool as in FIG. 5, is adaptedto work with coiled-in-coiled tubing. Adapting other tools to functionin a bottomhole assembly package connected to coiled-in-coiled tubingmay require only an appropriate sub to connect the tool fluidcommunication ports with the fluid communication capabilities of thecoiled-in-coiled tubing, or with the tool sections above. If multipletools are packaged in a bottomhole assembly, some provision will likelybe made to port the tool's own fluid communication ports with the fluidcommunication ports of the above tool as well as to port fluidcommunication through or around the tool in order to serve toolsconnected below. Such engineering and design parameters can be workedout as preferred bottomhole assembly packages develop. The greater thecommercial market for a particular tool package assembly, the greaterthe likelihood that fluid communication channels will be incorporatedinto the tool body self as opposed to being arranged in an ad hoc ortemporary fashion.

It is envisioned that pumps associated with a bottomhole assembly mayinclude jet pumps, chamber liftpumps, and/or electric pumps. Such pumpscould function as alternate systems to recover well effluent to thesurface for measurement or analysis. Electrical submersible pumps areknown. A wireline will likely extend through one of the twocoiled-in-coiled tubing conduits to establish electrical communicationbetween the surface and the bottomhole assembly package. The electricalcommunication could serve the functions of both power and communication,as is illustrated and taught in U.S. Pat. No. 4,898,236 to Sask,entitled “Drill Stem Testing System.” The important role of real timedata is discussed in the Sask patent. The wireline could include aconductor within a braided line. Fibre optic wireline cables are also apossibility. If the wireline is to be included in the coiled-in-coiledannular conduit, as opposed to the inner conduit, the coiled-in-coiledtubing would likely be concentric as opposed to multicentric. Any singleor multi-line conductor within a braided line or smaller coil tubingcould function as a communication cable.

A variety of measuring tools may fortuitously be included in abottomhole assembly package. Provision would be advantageously providedfor multiple pressure, temperature, logging or other measurements.

The apparatus for use in well operations may omit a packer associatedwith the tubing and/or bottomhole assembly, as the bottomhole assemblypackage may include multiple tools and function that have no need forpacking off. When a packer is included with the bottomhole assembly, oneconduit of the coiled-in-coiled tubing could advantageously be used tohydraulically set the packer. Inflatable/deflatable strata packers maybe appropriate for many operations.

The availability of the above apparatus, namely coiled-in-coiled tubingand an appropriate bottomhole assembly package, makes possible theperformance of a variety of novel, efficient and cost effective downholewell operations, performable in one run. For such operations, thecoiled-in-coiled tubing should be connected to the bottomhole assemblypackage such that both the inner and the annular fluid conduits are influid communication with the assembly.

The bottomhole assembly is to be located down a wellbore. Most easilythe assembly is injected down the wellbore attached to the distal end ofthe coiled-in-coiled tubing being injected from a spool. Oneadvantageous method of use of the above apparatus includes packing offbetween a portion of the wellbore and a portion of the tubing and/orassembly and pumping fluid down at least one of the two coiled-in-coiledtubing conduits for operations. Fluid, for instance, could be pumpeddown to set the packer. Fluid pumped down the conduit could also beadvantageously used to power tools and to circulate into the wellbore.Wellbore fluid could be produced up a conduit, simultaneously or insequence with pumping down to facilitate flushing operations.

For example, if a combination production/test and treatment injectiontool, such as that of FIGS. 5 and 5A, were to comprise the bottomholeassembly, together with a packer, the methodology could include firstsetting the packer amid the drilling fluid in a wellbore by using waterin a first conduit, preferably the annular conduit. The first conduitcould then be shut off and wellbore fluid below the packer produced upthe second conduit, preferably the inner conduit. The drilling fluid ormud remains in the wellbore tubing annulus above the packer. In thepresent example subsequent operation will not contaminate or otherwisedestroy the value of this drilling fluid by circulating extraneousmaterials through it.

If testing of the produced fluid indicates that a well treatment mightimprove production, valves can be opened that permit circulation betweenthe first conduit and the second conduit. Water in the first conduit andproduction fluid in the second conduit (and in the wellbore beneath thepacker to a certain extent) can be circulated out and a treating fluid,such as acid, pumped down. When the fluids are suitably flushed, thesecond conduit can be closed and the treating fluid, such as acid,injected into the wellbore below the packer through the first conduit.The treating fluid may be followed by water. Both conduits may then beclosed while the chemical acts. Production can be reestablished back upthe second conduit, producing first any residual fluids in the conduit,spent acid and then formation fluid.

It can be assumed that the acid injected down the first conduit wasfollowed by water such that when the acidizing is complete, waterremains trapped in the first conduit. The formation fluid can beadvantageously tested anew. If the test results on the producedformation fluid are now satisfactory, the packer can be deflated,particularly aided by using a conduit to depressurize the packerchamber, and the process repeated at another location. If the testresults are unsatisfactory, the flush and treatment cycle can berepeated, using the same or different treatment fluids. Straddle packerscan be used in lieu of a single packer to suitably isolate a productionzone.

If testing indicates that a zone produces water, a polymer squeezechemical could be applied through one conduit, such as the firstconduit, to wall off the zone from production. The success oreffectiveness of the polymer squeeze could be immediately subsequentlytested by production with the tool. In the above sequence of operations,the drilling fluid in the well above the packer has not beencontaminated by the necessity to flush any fluids through thewellbore-tubing annulus above the packer.

A packer might be set downhole such that it permits coiled-in-coiledtubing to slidingly reciprocate while the packer packs off between thewellbore and the tubing wall. Some treating operations such as sandvacuuming and/or jet cleaning require the movement of a tool duringoperation. Drilling also depends upon movement of the coiled tubingwithin the wellbore. A packer permitting the tubing to reciprocatethrough it, set at a build section, might permit, for instance, ahorizontal well to be overbalanced in its vertical section, havingdrilling fluid above the packer, and underbalanced in its horizontalsection below the packer. Gas could be pumped down one of the twoconduits with liquid down the other, both to the bit, to drill undervariably balanced conditions while providing adequate cooling andlifting power to the bit and at the same time a conduit carrying onlyliquid for acoustic communication and hydraulic fluid.

In one methodology, with or without a packer, fluid could be pumped downboth conduits to a bottomhole assembly where each fluid comprises eithera hydraulic operating fluid or a well treatment fluid. This methodologywould permit the mixing of chemicals downhole. For instance, a first andsecond chemical might pump more favorably unmixed, such as fracturingfluid and gel setting chemicals and/or gel breaking chemicals, or suchas two different acids. It is sometimes advantageous to have twodifferent treatment fluids that are not mixed until ready for use. Heatcould be generated downhole more safely by the mixture there of twochemicals.

Combustion downhole might be controlled by a controlled supply ofoxygen. Two different tools could be hydraulically operated, each havingtheir own independent hydraulic pressure and flow rate controlled atsurface, as a hydraulically operated bit and a hydraulically operatedorienting tool, or a hydraulically operated bit and a hydraulic jettingtool. One conduit could contain hydraulic fluid for operating a rotarycleaning jet while the other conduit contained a fluid, such as an acidfluid, for selectively dispensing out the rotating jets. Hydraulic fluiddown one conduit could operate a pump while a treating or jetting fluidcould be administered through the other conduit. In one embodiment arotating jet cleaning tool could be operated together with a sandvacuuming tool. Many such tools could be computer controlled throughreal time feed back data.

In another methodology the outer conduit could be used to providethermal insulation for fluid in the inner conduit. For example, viscousoil could be produced through the inner conduit while thermal insulationcould be provided by a fluid, such as a gas, air, a gel or otherinsulation material in the outer conduit. For the purposes of thepresent disclosure a vacuum should be considered as a “gas” fluid, as itrepresents a limiting condition for the presence of a gas. Suchinsulating fluid could keep the oil temperature up and thus the oilviscosity down so that the oil could be more readily brought to surface.

One utilization of the present invention includes a methodology in whichthe bottomhole assembly comprises at least a pair of valvedproducing/treating tools separated by a bottomhole assembly spacer.Wellbore fluid could be produced from two different locations, each up adifferent conduit. The embodiment could be operated with or withoutpackers. Advantageously the two producing tools could be separated by apacker in order to test alternative producing zones.

A surface computer system could be advantageously employed to recoverand analyze data in real-time in order to calculate reservoirparameters. The same surface computer system could be used to controlall downhole tool valves for the movement of all fluids and gases. Theapparatus and method advantageously includes capability for remote datatransmission from the well site to another location.

The present invention also includes optimal methods for assemblingcoiled-in-coiled tubing. These methodologies include extending a firstlength of coiled tubing essentially horizontally. A second inner coiledtubing length could then be pumped through the first coiled tubinglength and/or pulled through the first coiled tubing length, by means ofa cable, and/or injected through the first coiled tubing length by meansof a coiled tubing injector. Any combination of pumping, pulling andinjecting, together with lubricating between the coils, could be usedsimultaneously or sequentially to accomplish the assembling ofcoiled-in-coiled tubing.

BRIEF DESCRIPTION OF THE DRAWINGS

A better understanding of the present invention can be obtained when thefollowing detailed description of the preferred embodiment is consideredin conjunction with the following drawings, in which:

FIG. 1 illustrates typical equipment used to inject coiled tubing into awell.

FIGS. 2A, 2B and 2C illustrate a working reel for coiled tubing withplumbing and fittings capable of supporting an inner coil with an outercoil.

FIG. 3 illustrates in cross-section an embodiment for separating orsplitting inner and outer fluid communication channels into side-by-sidefluid communication channels.

FIG. 4 illustrates in cross-section an inner and an outer coiled tubingsection having a wireline within.

FIGS. 5 and 5A illustrate an embodiment of a downhole device or tool,adapted for attachment to coiled-in-coiled tubing, and useful forcontrolling fluid flow between a wellbore and an inner coiled tubingstring as well as between the wellbore and an annular region betweeninner and outer coiled tubing strings, and also useful for controllingfluid flow between the inner coiled tubing string and the annularregion.

FIG. 6 illustrates helixing of an inner coil within an outer coil in“multicentric” coiled-in-coiled tubing.

FIG. 7 illustrates an injection technique for injecting an inner coilwithin an outer coil to produce “multicentric” coiled-in-coiled tubing.

FIG. 8 illustrates a method of assembling “multicentric”coiled-in-coiled tubing.

FIG. 9 illustrates coiled-in-coiled tubing having wireline within theinner tubing and the inner tubing helixed within the outer tubing.

FIG. 10 illustrates coiled-in-coiled tubing having an inner tubingcentralized within an outer tubing and having a wireline extending inthe annulus between the inner and outer tubing.

FIG. 11 illustrates schematically a bottomhole assembly package.

FIG. 12 illustrates a bottomhole assembly including an assembly unitwhere a packer might be carried.

FIG. 13 illustrates coiled-in-coiled tubing attached to a bottomholeassembly located downhole in a wellbore having a packer sealing awellbore annulus at the build section and providing for reciprocation ofthe tubing within the packer.

FIG. 14 illustrates a horizontal method of assembly for coiled-in-coiledtubing.

FIG. 15 illustrates the use of computer control with coiled-in-coiledtubing and a bottomhole assembly.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS

FIG. 1 illustrates a typical rigup for running coiled tubing. This rigupis known generally in the art. In this rigup truck 12 carries behind itscab a power pack including a hook-up to the truck motor or power takeoff, a hydraulic pump and an air compressor. The coiled tubing injectingoperation can be run from control cab 16 located at the rear of truck12. Control cab 16 comprises the operational center. Work reel 14comprises the spool that carries the coiled tubing at the job site.Spool or reel 14 must be limited in its outside or drum or spooldiameter so that, with a full load of coiled tubing wound thereon, thespool can be trucked over the highways and to a job site. A typical reelmight offer a drum diameter of ten feet. Reel 14, as more fullyexplained in FIGS. 2 and 3, contains fixtures and plumbing and conduitsto permit and/or control communication between the inside of the coiledtubing string and other instruments or tools or containers located onthe surface.

FIG. 1 illustrates coiled tubing 20 injected over gooseneck guide 22 bymeans of injector 24 into surface casing 32. Injector 24 typicallyinvolves two hydraulic motors and two counter-rotating chains by meansof which the injector grips the tubing and reels or unreels the tubingto and from the spool. Stripper 26 packs off between coiled tubing 20and the wellbore. The well is illustrated as having a typical wellChristmas tree 30 and blowout preventor 28. Crain truck 34 provideslifting means for working at the well site.

FIGS. 2A, 2B and 2C illustrate side views and a top cutaway view,respectively, of a working reel 14 fitted out for operating withcoiled-in-coiled tubing.

FIG. 2A offers a first side view of working reel 14. This side viewillustrates in particular the plumbing provided for the reel to managefluid communication, as well as electrical communication, through theinner coiled tubing. The inner tubing is the tubing designated forcarrying the fluid whose communication should be safeguarded, fluid thatmight be hazardous. The coiled-in-coiled tubing connects with workingreel 14 through rotating connector 44 and fitting 45. Aspects ofconnector 44 and fitting 45 are more particularly illustrated in FIG. 3.This plumbing connection provides a lateral conduit 62 to channel fluidfrom the annular region between the two tubing lengths. Fluidcommunication through lateral conduit 62 proceeds through a centralportion of reel 14 and a swivel joint on the far side of working reel14. These connections are more particularly illustrated in FIGS. 2B and2C, discussed below. Fluid from inside the inner coiled tubing, as wellas wireline 66, communicate through high pressure split channel valvefixture 45 and into high pressure piping 46. High pressure channelsplitter 45 as well as high pressure piping 46 are suitable for H2Sservice and rotate with reel 14. Lateral conduit 62 also rotates withreel 14. Wireline telemetry cable 66, which connects to service downholetools and provide real time monitoring, controlling and data collecting,passes out of high pressure piping 46 at connector 47. Telemetry line66, which may be a multiple line, connects with a swivel joint wirelineconnector 42 in a manner known in the industry.

Swivel pipe joint 50 provides a fluid connection between the highpressure non-rotating plumbing and fittings connected to the axis ofworking reel 14 and the rotating high pressure plumbing attached to therotating portions of the drum, which are attached in turn to the coiledtubing on the reel. High pressure conduit 52 connects to swivel joint 50and comprises a non-rotating plumbing connection for fluid communicationwith the inner coiled tubing. Valving can be provided in the rotatingand/or non-rotating conduits as desired or appropriate. Conduit 52 canlead to testing and collecting equipment upon the surface related tofluid transmitted through the inner coiled tubing.

FIG. 2B offers a side view of the other side of working reel 14 fromthat shown in FIG. 2A. FIG. 2B illustrates plumbing applicable to theannular region between the two coils of the coiled-in-coiled tubing.Conduit 58 comprises a rotating pipe connecting with the other side ofreel 14 and conduit 61 providing fluid communication through a centralsection 60 of the reel. Conduit or piping 58 rotates with the reel.Swivel joint 54 connects non-rotating pipe section 56 with rotating pipe58 and provides for fluid communication with the annular region forfixed piping or conduit 56 at the surface. Piping 56 may be providedwith suitable valving for controlling communication from the annularregion between the two coiled tubing strings with appropriate surfaceequipment. Such surface equipment could comprise a source of fluid orpressurized fluid 76, indicated schematically. Such fluid could comprisegas, such as nitrogen, or water or drilling mud or some combinationthereof. Monitoring means 78, also illustrated schematically, may beprovided to monitor fluid within the annular region between the innerand outer coiled tubing. Monitoring equipment 78 might monitor thecomposition and/or the pressure of such fluid in the annular region, forexample.

FIG. 2C illustrates a top cutaway view of working reel 14. FIG. 2Cillustrates spool diameter 74 of working reel 14. Spool surface 75comprises the surface upon which the coiled-in-coiled tubing is wound.Surface 75 is the surface from which the tubing is reeled and to whichit is respooled. FIG. 2C illustrates wireline connector 42 connecting towireline 66 and from which electrical line 67 is illustrated asemerging. Wireline 66 and electrical line 67 can be complexmulti-stranded lines. Dashed line 72 illustrates the axial center ofworking reel 14, the axis around which working reel 14 rotates. Theright side of FIG. 2C illustrates rotating plumbing or conduit 58 andnon-rotating plumbing or conduit 56, both illustrated in FIG. 2B. Theyprovide for fluid communication at the surface with the annular regionbetween the coiled tubing strings. Conduit 61 communicates throughchannel 60 in working reel 14 to connect conduit 58 with lateral 62 onthe far side of working reel 14. Conduit 61 and channel 60 rotate withthe rotation of the drum of working reel 14. The left side of FIG. 2Cillustrates rotating pipe 46 and non-rotating pipe or conduit 52. Asdiscussed in connection with FIG. 2A, these sections of pipe or conduitprovide for fluid communication between the inner coiled tubing stringand surface equipment, if desired.

Split channel plumbing 45 providing lateral 62 is illustrated incross-section more particularly in FIG. 3. Wireline 66 is shown enteringplumbing fixture 45 from the left side and emerging on the right side influid communication channel 83. Channel 83 is in communication with theinside of the inner tubing string. Bushing 49 anchors inner tubing 102within plumbing fixture 45. Packing and sealing means 51 preventscommunication between the annular area 80, defined between outer tubing100 and inner tubing 102, and fluid communication channel 83. Fitting 44anchors outer coiled tubing 100 to fixture 45.

FIG. 4 illustrates in cutaway section components of coiled-in-coiledtubing. FIG. 4 illustrates cable or wireline 66 contained within innertubing 102 contained in turn within outer tubing 100. Cable 66 couldcomprise fiber optic cable for some applications. Channel 82 identifiesthe channel of fluid communication within inner tubing 102. Annular area80 identifies an annular region between tubings, providing for fluidcommunication between inner tubing 102 and outer tubing 100 if desired.A typical width for inner tubing 102 is 0.095 inches. A typical widthfor outer tubing 100 is 0.125 inches.

FIG. 5 illustrates an embodiment, schematically, of a downhole toolusable with coiled-in-coiled tubing, and in particular useful for drillstem testing. Tool or device 112 is attached by means of slip connector116 to the outside of outer tubing 100. Tool 112 is shown situated inregion 106 defined by borehole 120 in formation 104. Packers 108 and 110are shown packing off between tool 112 and borehole 120 in formation104. If formation 104 is capable of producing fluids, they will beproduced through wellbore 120 in the zone defined between upper packer110 and lower packer 108. Tool bull nose 118 lies below lower packer108.

Indicated region 122 in tool 112 refers to a general packer and toolspacer area typically incorporated within a device 112. Spacers areadded to adjust the length of the tool. Provision may be made in thisspace, as is known in the art, to collect downhole samples for retrievalto the surface. Indicated region 124 in tool 112 refers to a generalelectronic section typically incorporated within a device 112. Anchor114 anchors inner coiled tubing 102 within outer coiled tubing 100 atdevice 112 while continuing to provide means for fluid communicationbetween annular region 80 between the two tubing lengths and portions oftool 112.

Valving provided by the tool is indicated stylistically in FIG. 5. Valve130 performs the function of a circulation valve, permitting circulationbetween annular region 80 between the coils and fluid communicationchannel 82 within inner coiled tubing 102. Valve 130 could be used tocirculate fluid down annular region 80 and up inner tubing channel 82,or vice versa. Wireline 66 would commonly terminate at a wirelinetermination fitting, illustrated as fitting 69 in tool 112. Valve 132indicates valving to permit fluid communication between inner channel 82and the borehole above upper packer 110. Valve 134 permits well fluidsfrom formation 104 within borehole annular region 106 to enter intodownhole tool 112 between upper packer 110 and lower packer 108 and fromthence into inner tubing conduit 82. Valve 136 indicates an equalizingvalve typically provided with a tool 112. Valve 131 provides for theinflation of packers 110 and 108 by fluid from annular regions 80. Valve133 is available for injecting fluids from annular region 80 into theformation, for purposes such as to stimulate formation 104. Connector105 between the tubing and downhole tool could contain an emergencyrelease mechanism 103 associated therewith, as is known in the art.Valve 138 provides for deflating packers 108 and 110.

FIG. 6 illustrates a helixed inner coil 102 within an outer coil 100forming “multicentric” coiled-in-coiled tubing 21, shown strung in well120 through formation 104. It is believed that when hung in a verticalwell a coiled tubing, such as outer coil 100, would not hang completelystraight. However, the weight of the coil would insure that outer coil100 hung almost straight. Cap 150 is shown attached to the distal end ofouter coil 100, downhole in well 120. Inner coil 102 is illustrated ashelixed within outer coil 100. This helixing provides a lack ofconcentricity, or coaxiality, and is intentional. The intentionalhelixing provides a multicentricity for the tubes, as opposed toconcentricity or coaxiality. The helixing can be affected between aninner coil 102 and an outer coil 100 and is believed will not alwaystake the same direction. That is, the helixing might alternate betweenclockwise and counterclockwise directions. Inner coil 102 is illustratedin FIG. 6 as having its weight landed upon bottom cap 150 attached toouter coil 100. In this fashion, the weight of inner coil 102 is beingborne by outer coil 100, illustrated as hung by a coiled tubing injectormechanism 24. Alternately, the weight of inner coil 102 could be landedon the bottom of well 120, or cap 150 could sit on the bottom of well120, thereby relieving outer coil 100 of bearing the weight of innercoil 102.

FIG. 7 illustrates inner coiled tubing 102 spooled from spool 152 overgooseneck 154 and through inner coiled tubing injector 156 into outercoiled tubing 100. Outer coiled tubing 100 is illustrated as hung bycoiled tubing injector 24 into well 120 in formation 104.

FIGS. 8A through 8F illustrate a method for assembling multicentriccoiled-in-coiled tubing 21 on reel 14, as illustrated in FIG. 8G. FIG.8A illustrates spool 152 holding inner coiled tubing 102 sitting besidewell 120. With spool 152 is inner coiled tubing injector 156 and innercoiled tubing gooseneck support 154. Also at well site 120 is outercoiled tubing spool 158, outer coiled tubing injector 162 and outercoiled tubing gooseneck 160. FIG. 8B illustrates outer coil 100 beinginjected by coiled tubing injector 162 into well 120 from spool 158 andpassing of a gooseneck 160. FIG. 8C illustrates outer coiled tubing 100hung by outer coiled tubing injector 162 over well 120. Gooseneck 160and spool 158 have been removed. Outer coiled tubing 100 is shown havingcap 150 affixed to its distal or downhole end. FIG. 8D illustrates innercoiled tubing 102, injected and helixed into outer coil 100 hung in well120. Inner coil 102 is injected from spool 152 over gooseneck 154 and byinjector 156. The bottom of inner coil 102 is shown resting upon cap 150at the downhole end of outer coil 100, hung in well 120 by outer coilinjector 162. FIG. 8E illustrates inner coil 102 being allowed to relaxand to sink, to helix and to spiral further, inside outer coiled tubing100 hung by injector 162 in well 120. FIG. 8F illustrates respoolingcoiled-in-coiled tubing 21 onto working reel 14 using outer coiledtubing injector 162 and outer coiled tubing gooseneck 160. Outer tubing100 has been connected to reel 14. If separate means for hanging outertubing 100 are provided, the operation can be carried out with onecoiled tubing injector and one gooseneck.

In operation, the safeguarded method of the present invention for thecommunication of fluid from within a well is practiced with coiledtubing carried on a spool. The method is practiced by attaching a distalend of coiled-in-coiled tubing from a spool to a device for controllingfluid communication. The device, a specialized tool for the purpose,will be inserted into a well. (The safeguarded method for fluidcommunication would also, of course, be effective on the surface.Safeguarded communication from within a well offers the difficultproblem to solve.)

Coiled-in-coiled tubing comprises a first coiled tubing length situatedwithin a second coiled tubing length. A first channel for fluidcommunication is defined by the inside tubing length. The device or toolattached at the distal end of the coiled-in-coiled tubing controls fluidcommunication through this first inner communication channel. The devicemay also control some fluid communication possibilities through anannular region as well. An annular region is defined between the firstinner coiled tubing length and the second outer coiled tubing length.Fluid communication is also to be controlled, at least to a limitedextent, within this annular region. At the least, such control shouldextend to sealing off the annular region to provide the margin of safetyin the case of leaks in the inner tubing. Preferably, such control wouldinclude a capacity to monitor the fluid status, such as fluidcomposition and/or fluid pressure, within such region, for leaks.Preferably such control would include a capacity to pressurize aselected fluid within the annular region, to more speedily detect leaks.In preferred embodiments, the annular region may also function as asecond fluid communication channel.

The coiled-in-coiled tubing is injected from a spool into the well.Primary fluid is communicated through the inside tubing length from thewell to the spool. Of course, fluid could also be communicated in asafeguarded manner from the spool to the well, if such need arose.

The primary fluid may remain contained within the inside tubing length,as in a closed chamber, to minimize risk. Alternately the fluid may becommunicated from the inside tubing length through a swivel jointlocated upon the spool to other equipment and/or surface containers. Thecoiled-in-coiled tubing is eventually respooled.

The device for controlling fluid communication through the inside tubinglength usually comprises a specialized tool developed for multiplepurposes, fitted to operate in conjunction with coiled-in-coiled tubing.The tool may communicate electronically through a wireline, probablymultistrand, run through the inside tubing. The tool may also collectone or more samples of fluid and physically carry the samples uponrespooling, to the surface. The tool may further contain means formeasuring pressure.

The annular region between the inside and the outside coiled tubingprovides the safeguard, the secondary protective barrier in case ofleaks in the inside tubing, for the present method for fluidcommunication. For that reason, as mentioned above, fluid in the annularregion should at least be controlled in the sense that control comprisessealing off the annular region. As discussed above, preferably, thecontrol includes monitoring fluid status within the annular region, suchas fluid composition and/or fluid pressure, and may include supplyingpressurized fluid to the annular region, such as pressurized water,inert gas or nitrogen, drilling mud, or any combination thereof. Thepressure of such monitoring fluid can be monitored to indicate leaks ineither of the coiled tubing walls. Overpressuring the annular regionwould ensure that a leak in either the inner tubing wall or the outertubing wall would result in annular fluid evacuating the annular regionand invading the inner tubing string or the outside of thecoiled-in-coiled tubing. Such overpressurization in particular guardsagainst potentially hazardous fluid from inside the inner tubing everentering the annular region.

Upon the indication of a leak in either coiled tubing wall, the primaryfluid communication in the inner tubing could be terminated. The wellmay also be shut in by closing the valve and/or the well may be killedby deflating the packers. A blowout preventor (BOP) could be activated,if necessary.

The present safeguarded method for fluid communication is applicable towork within a wellbore as well as in a cased well or well tubing. Suchwellbore, cased well or well tubing may itself be filled with fluid,such as static drilling fluid.

The device or tool for controlling fluid communication from the wellfrequently includes a packer or packers for isolating a zone ofinterest. The annular region between the tubing walls can be used as afluid communication channel for supplying fluid to inflate the packers.The annular region could also be used as a fluid communication channelfor supplying a stimulating fluid, such as acid, or a lifting fluid suchas nitrogen, downhole to the well.

The coiled-in-coiled tubing is attached at the surface to a working reelor spool. The spool for coiled-in-coiled tubing will contain means forsplitting the fluid communication channel originally from within theinner coiled tubing from the potential communication channel defined bythe annular region between the coiled tubing lengths. Generallyspeaking, the inside length also should be no longer than 1% of theoutside length.

One aspect of the present invention provides improved apparatus forpracticing above the method, the improved apparatus comprising“multicentric” coiled-in-coiled tubing. Such multicentriccoiled-in-coiled tubing includes several hundred feet of continuousthrustable tubing, coiled on a truckable spool. The tubing includes afirst length of coiled tubing of at least ½ inch outside diameterhelixed within a second length of coiled tubing. Generally speaking,taking into account the variations possible between OD's of inside andoutside tubing and wall thickness, when measured coextensively the firstinside length would be at least 0.01% longer than the second outsidelength. Generally speaking, the inside length also should be no longerthan 1% of the outside length. (It is of course clear, that either theinside length or the outside length could be extended beyond the otherat either the spool end or at the downhole end. “Measuringcoextensively” is used to indicate that such extension of one lengthbeyond the other at either end is not intended to be taken into accountwhen comparing lengths.)

When coiled-in-coiled tubing is spooled, it is believed that the innerlength, to the extent it overcomes friction, would tend to spool at themaximum possible spool diameter. That is, the inner length would tend tospool against the outer inside surface of the outer length. Suchtendency, if achieved, would result in a significantly longer length forthe inside tubing versus the outside tubing. The difference in length issignificant because the present inventors anticipate that if thecoiled-in-coiled tubing were allowed to assume this maximum spooldiameter position on the spool and the ends were fixed to each other,then when straightened, the inner tubing would tend to fail or bucklewithin the outer tubing.

“Concentric” or “coaxial” tubing comprises, of course, strands of thesame length. Centralizers could be used to maintain an inner tubingconcentric or coaxial within an outer tubing on a spool. Alternately, aninner tubing could be inserted coaxially in a straightened positionwithin an outer tubing, and the two ends of the two tubings could thenbe affixed together to prevent retreat of the inner tubing within theouter tubing upon spooling. For instance, an inner coiled tube could beinjected within an outer coiled tube hung in a vertical well, possiblyusing means to minimize friction there between, such that, measuredcoextensively, the lengths of both coils would tend to hang straight andbe very close to the same length. The inner coil would not be helixedwithin the outer coil. To help straighten out any undesired helixing,the inner coil could latch on to a cap attached to the bottom of thehung outer coil. The weight of the outer coil could then be picked upand carried by the inner coil if the inner coil were lifted subsequentto latching onto the end cap. So lifting the inner coil, bearing notonly its own weight but part or all of the weight of the outer coilwould help straighten the inner coil out within the outer coil and alignthe two coils. This solution, “coaxial” or “concentric” coils isbelieved not to be optimal. Coaxiality might result in an unacceptablelevel of compression and/or tension being placed upon on portions of oneand/or the other length while resting on the spool.

It is proposed by the present inventors that the “multicentric”coiled-in-coiled tubing disclosed herein best solves the above problemswithout involving the complexity of centralizers. Helixing the innercoil within the outer coil provides an advantageous amount of frictionalcontact between the two coils, frictional contact that is dispersedrelatively uniformly. Furthermore, the inner coil has a certain amountof flexibility in which to adjust its configuration longitudinally uponspooling in and out. The helixed inner coil should not buckle or failupon respooling and spooling. The frictional contact is sufficientbetween the helixed inner coil and outer coil that unacceptably highareas of compression or tension between the two coils are not createdwhile on the spool. The helixed inner coil, under certain circumstances,may even enhance the structural strength of the coiled-in-coiled tubingas a whole.

FIG. 9 illustrates an embodiment for coiled-in-coiled tubing wherein aninner coil is helixed within an outer coil and a wireline cable or fibreoptic cable or braided cable, or the like, is included within theconduit provided by the inner coil. FIG. 10, in contrast, illustrates aconcentric coil-in-coil arrangement. In FIG. 10, centralizer CNmaintains inner coil tubing ICT, defining a first conduit IC,centralized within outer coiled tubing OCT. A second annular fluidconduit AC is defined in the annulus between inner coil ICT and outercoil OCT. FIG. 10 illustrates wireline W located in the annular conduitAC.

FIG. 11 illustrates schematically a bottomhole assembly package BHAcomprised of multiple units. Coiled-in-coiled tubing CNCT havingwireline W located inside the inner coil is shown affixed to unit U1.Unit U1 may be a sub, preferably a multi-purpose coiled-in-coiled tubinghead for connecting to a bottomhole assembly package such that bothconduits IC and AC are in fluid communication with package BHA.

In bottomhole assembly BHA, each unit, U2-U8, could indicate a differenttool or measuring instrument or packer or spacer. Bottomhole assemblyBHA is shown with the tools and/or instruments mated together and inpreparation for mating its upper end with the coiled-in-coiled tubinghead. Units U1 through U8 would be provided for mating such that fluidcommunication is continued through most, if not all, units with both thefirst conduit IC and the second conduit AC, as well as with wire line W.

FIG. 12 illustrates that a packer might well be carried in an earlyunit, such as Unit U2. FIG. 13 illustrates packer PK set in a buildsection of a bore hole. One of the conduits defined by thecoiled-in-coiled tubing could be used to supply fluid to set the packer,as well as to assist in deflation or unsetting. Packer PK is illustratedas having an inner sleeve through which the tubing CNCT sealinglyreciprocates. Analogous packers have been taught and could be adapted towork with coiled tubing.

FIG. 14 illustrates alternate methods for the construction ofcoiled-in-coiled tubing. For illustrative purposes, FIG. 14 illustratesouter coiled tubing OCT extended essentially horizontally. Inner coiltubing ICT is illustrates as being simultaneously pulled through outercoil OCT by cable CB. Inner coil ICT is also being thrust into outercoil OCT by a coil tubing injector, illustrated schematically as CTI. Inaddition, inner coil ICT is illustrated as connected at its distal endwith a plug PL. Pump P is illustrated as pumping fluid in the annulusbetween outer coil OCT and inner coil ICT thereby pressuring plug PL topump inner coil ICT through outer coil OCT.

FIG. 15 illustrates the use of computer control for monitoring andoperating complex operations such as alternating testing, treating andtesting. Computer CPU is illustrated in electrical connection throughline L with the wire line WL that extends through the coiled-in-coiledtubing CNCT and into and through connectors located in the working reelor spool R/S. Computer CPU can collect real time data through wirelinecommunication as well as control downhole tools such as the setting anddeflating of packers, the opening and closing of valves, the operatingof drills and orienting tools and jetting tools and pumping tools andmotors.

EXAMPLE TEST, TREAT, TEST SYSTEM

The flow testing of oil and gas reservoirs is a critical operation usedby operators in both openhole and cased hole applications. Theinformation gained from openhole Drill Stem Tests (DST), permeability,flow rates, skin damage and water production is used to confirm welldeliverability and justifies casing the well. Alternately many wells areproduction tested after being cased to gather additional wellinformation establishing reservoir limits and the presence of wellboreskin damage. In wells with large pay zones (horizontal), productiontests are often used to selectively determine the source of wellproduction, hydrocarbon or water, to allow remedial workovers.

Although well testing is common in nearly all reservoirs, the testing ofsour gas wells and horizontal wells is still a significant challenge foroperators and service companies alike. The testing of sour wells hasbeen very limited due to the concerns of H₂S embrittlement of drillpipeand overall wellsite safety as sour gas is produced to surface. In mostcases, without DST data, operators must rely on limited geological andopenhole log evaluation to establish well deliverability allowingjustification to case the well. In horizontal wells the challenge is toselectively test the horizontal section in the well and use thisinformation to implement remedial stimulation to improve production.

The new technology of the current example uses an inflatable straddlepacker tool deployed into vertical or horizontal wells using a“Coil-in-Coil” coiled tubing string configuration. An electricalconductor is located inside the inner string which allows for “realtime” formation, evaluation and tool operation. The inner coil string isused for all well flow and stimulation operations, with the coil-in-coilannulus utilized for circulation operations and packer elementinflation. More importantly, the outside string also provides forpressure monitoring, flow containment and well control in the unlikelyevent of a failure of the inner string.

This is in contrast to the testing of wells that has been part of theoil and gas business since the first oil wells were drilled many yearsago. Historically, after drilling a well to the target formation, manyoperators will undertake a flow test of the formation of interest usingDST tools run back into the well on the drillpipe. This drillpipe, oftenempty, is positioned over the zone of interest and then the packerelements are expanded through pipe rotation or setdown weight. A valvein the DST tool is opened allowing formation fluids to enter theevacuated drillpipe, and if adequate bottom hole pressure (BHP) and flowcapacity is present, this results in well production to surface. If,however, the BHP is not sufficient, the well will continue to flow intothe drillpipe until its hydrostatic pressure equals the reservoirpressure. The tools are then closed and recovered from the well and theproduced fluid is measured and analyzed. In the early years of DST use,only well flow data was available. This information, combined withopenhole logs, was valuable in the confirmation that well potential wassufficient to warrant casing the well and pursuing a completion. Lateradvancements in the understanding of well flow and reservoirdeliverability resulted in the use of downhole pressure recorders andpressure transient analysis to obtain information on formationpermeability, wellbore skin damage and DST tool performance. Some oftoday's DST tools use data transmission technology to enable therecovery of the pressure drawdown and build-up data during the test,allowing optimization of well flow and buildup durations. The value ofthe DST data can not be understated as a means of gathering criticalwell information prior to committing to the cost of casing andcompleting wells whose deliverability might be marginal.

Unfortunately the development of sour gas and oil formations and therecent growth of horizontal drilling have presented significantchallenges for the use of conventional DST tools. Sour wells arepresently drill stem tested in very limited applications due to safetyconcerns and the overall cost. During the testing of a sour well, thedrillpipe is exposed to H₂S in the produced oil or gas. Since mostdrillpipe is made of high tensile strength steel with a RockwellHardness in excess of 22Rc, the drillpipe is susceptible to H₂Sembrittlement. As a result, most operators will not use the drillpipefor sour flow tests but will stand back or lay down the drillpipe andpick-up a new string of sour service tubing to conduct the DSToperation. After the testing operations are completed, the tubing islaid back down and the drillpipe used to either abandon the well orcondition the hole for casing operations.

DST data is important in all well evaluations but especially so in thecase of carbonate reservoirs since openhole log information may notadequately address the question of well deliverability with the samedegree of confidence available on similar logs for sandstone reservoirs.Consequently, the operator is very interested in any additionalinformation on well deliverability, reservoir pressure and wellbore skindamage that will give the operator confidence in the decision to case orabandon the well. The decision to run casing and then subsequentlycomplete the well will cost the operator in the order of CS 400k-600kbased on a typical 11,500 foot (3,500 m) sour gas well. However, thedecision to abandon the well and bypass a significant find has a moreserious impact on future profitability.

Another limitation of current DST tool technology is the ability toquickly evaluate multiple zones in a well and to recover test fluidsfrom each test. In a conventional subhydrostatic DST with drillpipe,formation fluid is recovered into the drillpipe. To analyze this fluidfor water, drilling filtrate and hydrocarbon requires the retrieval ofthe DST tools to surface. In addition, although real-time datatransmission is available via Wet-Connect and Electro-Magnetic systems,both have their challenges at present. With the Wet-Connect system,every time one needs to reset the tools across a new pay zone thewire/wet connect needs to be pulled. Once the tools are across the newpay zone, wireline needs to be run in the hole (RIH) to the wetconnector and re-establish electrical connection. With the EM system,depth and geology are its main limitations.

Horizontal Wells

Horizontal wells present a similar challenge for existing well testingtools although the requirement is not to obtain data to support a “runcasing—don't run casing” decision but to obtain well flow and pressuretransient data to allow for maximizing well production and recoverablereserves. Horizontal drilling has developed as a cost effectivetechnology to enhance well production in existing pressure depletedfields or tight low deliverability reservoirs. Unfortunately, althoughmost horizontal wells result in increased well production, bothhydrocarbon and water, the operator has limited resources to confirmfrom where along the extensive openhole section the respective wellflows originate.

Many of the most successful horizontal wells are in heterogeneousreservoirs where formation geology varies significantly resulting inbypassed production when using vertical well development. In mosthorizontal wells, the openhole section is extensive in length withnumerous changes in well porosity and permeability along the openholelength. Consequently well deliverability varies considerably both inhydrocarbon and water production. In vertical wells, current openholeand cased hole logging tools can be used to confirm well deliverabilitybased on previous well experience. Unfortunately the use of these sametools in horizontal wells is not as effective. Similarly the use ofproduction logging tools, although successful in vertical wells, is verylimited in horizontal wells due to openhole conditions, openhole length,stratified flow, subhydrostatic reservoirs and cost.

The most viable technology presently for use in testing horizontal wellsin Canada has been the use of inflatable straddle packers run into thewell on jointed tubing and set across a selected area of the openhole.Pressure recorders are located in the BHA and the well is swabbed in toobtain inflow data specific to the test zone after which the well isshut-in at surface for the pressure build-up. The straddle packerassembly is then pulled out of hole (POOH) and the recorded pressure andrecovered fluids analyzed to predict wellbore skin and assess productiondata. If skin is evident, a decision is made to undertake a selectivestimulation which would require running back into the well and resettingthe packers across the production zone of interest. Afterstimulation/evaluation process must be repeated multiple times to covera 3,000 foot (900 m) openhole section. Obviously this procedure is bothtime consuming, expensive and will produce data of limited quality.

In both sour well development and horizontal well development, there isa need for a downhole tool design and deployment system that will allowfor the straddle packer testing of multiple zones, the recovery ofreservoir fluid sample without the need to POOH and real-time pressuretransient data. The design should also allow for the stimulation or flowmodification of the specific evaluation zone based on the real-timeevaluation of the flow composition, rate and pressure transient datawithout having to remove the toolstring.

While the previous discussion reviewed the limitations of currenttechnologies to satisfy the evaluation/stimulation/evaluationrequirements of DST's for vertical sweet and sour oil and gas wells andsimilar service operations for horizontal wells, the followingdiscussion reviews the operational features of the optimum test systemand the benefits of these features for actual operations.

For Sour Production Flow Capabilities, the system must be capable ofcontinuous exposure to significant acid gas conditions without concernfor axial load conditions. The minimum number of connections and a meansof monitoring the condition of the string would be a plus.

For Real-Time Data Recovery And Tool Control, the recovery of data by areal-time system is critical to optimizing both flow and pressurebuild-up durations as well as optimizing stimulation or flow profilemodification treatments. The pressure buildup data must be of sufficientlength and sensitivity for pressure transient analysis of wellborepermeability and skin. The optimum system would consist of wirelinetelemetry (higher data transfer than other present systems) that allowedfor continuous surface readouts and downhole tool operation without pipemovement.

For Sample Recovery To Surface, in both vertical and horizontal wells,there is a need to recover bottomhole samples to surface during the testif the well's BHP is inadequate to support continuous flow. In somecases, it would be advantageous if the fluid could be recovered duringthe test while the well was shut-in at the formation face for build-up.

For Stimulation/Flow Profile Modification Capabilities, in both thehorizontal and vertical case, there is benefit to undertake a formationtreatment while the tools are still set across the pretested interval.This helps minimize packer resets and enables evaluation during andafter the stimulation is complete. Real time read-outs during thetreatment would allow one to optimize the treatment. How better tomaximize production than to measure a wellbore skin, stimulate to removethe wellbore skin, unload the treatment fluids and then re-evaluate toconfirm results all with-in the same test interval and immediate timeframe.

For Gas Flow Capabilities, minimum gas flow capability is preferably,although not necessarily, in the order of 2-3 MMCF/day to ensureadequate reservoir drawdown to confirm reasonable gas flow rates at acorresponding formation flowing pressure. In addition the drawdown isrequired to allow for sufficient pressure build-up data for the pressuretransient analysis.

Minimum liquid flow capability is preferably, although not necessarily,in the order 200-300 bbls/day to again ensure adequate reservoirdrawdown for deliverability forecasts and pressure build-up analysis.

When drawing down openhole sections with large upset tools, the abilityto get stuck is greatly increased. Work history with inflatable packersin openhole DST situations shows that overpulls up to 20,000 pounds(8,900 daN) are sometimes required. The ability to underbalance theinner string slightly so as to “suck” the inflatable packer onto itsmandrel would be beneficial since all inflatable packers retain some setafter their first inflation. Also the ability to circulate from below todisturb or dissolve debris that might have accumulated on top of thepackers while they were set would be advantageous.

Of the 6,000 DST's carried out in Canada during 1995, over 98% wereshallower than 11,500 feet (3,500 m).

Straddling the right zone is crucial. Real time gamma and CCLincorporated into the tool suite would alleviate most concerns.

Since no openhole section is ever true, an inflatable element ispreferred to allow setting in minor washouts. Since one of the tool'srequirements is to test multiple zones quickly, a straddle configurationis required.

The surface equipment is very similar to a conventional coiled tubingwireline logging operation. Basically a standard coiled tubing unit plusone monitoring truck gathers the downhole DST data and operate thedownhole electrically actuated valves. The part of the CT surface layoutthat has been modified is the work reels which have two rotating joints,one for the inner coil and the other for the coil-in-coil annulus, plusone standard wireline collector. This will allow continuous logging(CCL/gamma), the ability to operate downhole valves plus gather pressureand temperature data while RIH/POOH and continuous circulation througheither annulus. It will also allow the system to be of a closed loopdesign so that sour/hydrocarbon based fluids do not need to be purgedwhenever the tools need to be RIH/POOH.

The Coiled Tubing String Configuration consists of a 2.375″ (60.3 mm)exterior coil with an 1.25″ (31.8 mm) coil placed inside. Inside the1.25″ coil resides a 3 conductor wireline cable. All sour/corrosivefluids will travel only through the 1.25″ while fluid for inflating thepackers or gas lifting the well in will be pumped down the coil-in-coilannulus. Pulls and pushes by the injector head will only be subjected tothe exterior coil. With this larger size coil, good horizontal reach isachievable, even with a heavy BHA.

The Coiled Tubing—DST Connector, due to the weight (2,000 lbs.), OD (5ins.) and length (+/−30-90 ft.) of the BHA, will be deployed in asimilar manner to a standard DST. After having been hung below therotary table in a set of slips, the CT injector will be swung over theBHA and connected. This connector has built into it a safety release,should the BRA become stuck while downhole, plus a 3 conductor feedthrough. Due to the difficulty of rotating either end of the assemblyduring make-up, it latches in a similar manner to a snap tight.

The heart of the BHA consists of two microprocessors connected throughthe wireline to a computer at surface. This allows continuous two waycommunication with the electronic section incorporated in the BHA. Thesystem is capable of full data acquisition as well as complete controlof all downhole functions.

Dual inflatable packers provide the ability to isolate discreet segmentsof the wellbore during flow tests or stimulation/flow profilemodification treatments. Inflation of the packers is accomplished byapplying pressure through the coil-in-coil annulus. Since this annuluscan be circulated to clean fluids (with returns taken up the 1.25″), iteliminates the potential plugging of inflate ports with well debris. Italso eliminates the potential of having the inner packer cavity filledwith sour, corrosive, hydrocarbon or aromatic fluids. The pressurewithin the packers, as well as the external wellbore pressure iscontinuously monitored throughout the operation.

Unlike conventional inflatable packer systems where pressure after atest can only be equalized, these packers can be RIH and POOH in anunderbalanced state (less pressure inside than out). This keeps thepackers fully collapsed and reduces the potential for encounteringwellbore bridges while running into the well or having the packers stuckafter deflation due to accumulated debris on top of them. It alsoreduces the chance of swabbing or surging the well while POOH/RIH.

The minimum bottom hole pressures at which various continuous productionrates can be obtained in a 11,500 foot (3,500 m) vertical well throughthe inner 1.25″ string are shown below. In the case of oil, productionis aided by nitrogen gas lift with the nitrogen being supplied down theannulus between the inner and outer CT strings.

Bottomhole Flow Wellhead Flow Pressure Pressure Gas Flow Rate BHFP WHFP(MMscf) (psi) (psi) 3 4450 206 2 2965 180 1 1520 187 Oil Flow Rate BHFPWHFP (bpd) (psi) (psi) 300 4000 160 200 3200 170 100 2200 220

Four (See FIG. 5A) of the downhole fluid control valves are computercontrolled, electronically actuated valves, which have been field provenin existing Drill Stem Testing (DST) systems. One is hydraulic. Thesevalves control the flow of fluids between the various components of thesystem. They are detailed below:

The first valve controls the flow of fluids from the annulus between thestraddle packers and the inner coiled tubing string. This “Flow Valve”(VI) normally controls the flow of formation fluids from the well intothe inner coil string and is a two position (open/closed) valve. It canalso be used to inject fluids from the inner string into the wellborebetween the two packers for stimulation, flow profile modification orcirculation purposes.

The “Inflation Valve” (V2) is a three position valve which in the“Inflation/Deflation” position allows fluid from the coil-in-coilannulus to be pumped into the packers for inflation purposes or todischarged this pressure at the conclusion of a test. The “Closed”position locks in whatever pressure (negative/positive) that is insidethe packers allowing pressure control of the coil-in-coil annulus. Inits third position, “Circulation”, fluid can be circulated between theinner coil and coil-in-coil annulus in either direction.

The “Equalization Valve” (V3) is a two position (open/closed) valvewhich allows fluid communication between the three segregated wellboreareas that are created when the two inflate packers are inflated. Theone above and below the straddle packers and the one between the twopackers. This helps equalize the pressure above and between the packersbefore deflating them. It also nullifies the chance of fracturing thezone of interest while the packers are still inflating (trapping fluidbetween the two packers before full expansion has occurred).

The “Injection Valve” (V4) is a two position (open/closed) valve whichprovides the ability to pump fluids down the coil-in-coil annulus andinject them into the wellbore annular region.

The “Relief Valve” (V5) is a hydraulic, shear pinned valve that protectsthe packers from over inflation but has a secondary purpose. Namely,should the electronic signal to surface ever fail, the overpressurization of this valve will open it up allowing the packers todeflate.

The following pressures are monitored continuously during all operationsat a 5 second sample rate:

Surface:

1. Inner coil (closed chamber or open flow pressure measurements).

2. Outer coil pressure.

Downhole:

1. Outside pressure between the packers (formation pressure), twogauges.

2. Wellbore hydrostatic pressure.

3. Inflation pressure within the packers.

4. Inner coil above the flow valve (recovery pressure).

5. Coil-in-coil annulus pressure.

Downhole temperatures are also recorded continuously. A Gamma Ray andCCL correlation log is incorporated into the tool suite to provide welldepth control for critical testing and stimulation operations whileRIH/POOH and setting the packers.

One of the primary reasons for the development of this system wassafety, particularly in the application of testing sour oil and gaswells. There are a number of safety features which are inherent withinthe design of this system and address safety. These include:

Pressure and fluid containment barriers are provided by the coil-in-coilsystem. Continuous monitoring of the outer coil's pressure allows anyleak in the inner coil to be detected immediately and testing halted.

Materials of Construction for Equipment: All of the materials used inthe fluid handling components of this system are to NACE MR-175specifications. The coiled tubing is manufactured from an A-606 Type 4,Modified metallurgy which has been used in numerous applications in sourenvironments over the years. The wireline sheath is made from Incology825, and the downhole tools from either 4140 carbon steel heat treatedto 18-22 Rc or from 17-4PH stainless steel heat treated to H1150÷1150specifications.

The small volume of the inner coiled tubing string minimizes the amountof sour fluids and hydrocarbons contained in the test string and reducesthe risk in well control situations.

Retrieving the test tools with the packers in an underbalanced pressurecondition reduces the risk for swabbing the wellbore fluids whilepulling out of the well.

If the BRA is stuck and conventional methods can not free it, the BHAcan be released by pressurizing up the inner string. If electrical powerhas also been lost and the valves are in the open position, tension canbe applied to the BHA to close a downhole check valve, allowingpressurization.

If electrical power is lost and the packers are still inflated, pressurecan be applied down the coil-in-coil annulus to open a deflate port. Ifthe downhole valve is open, an orifice downhole still allows one togenerate enough differential pressure to be generated when pumping toopen the port.

The procedures to be followed will vary depending on the wellconfiguration and the objectives of the evaluation and/or stimulationprogram for the well. The following procedures include the most commonanticipated situations:

Tripping BHA Into the Well for Well Evaluation

1. Inner string is air or nitrogen filled, depending on well depth.

2. Outer string is partially or fully liquid filled, depending upon BHP.

3. Pressures in each of the two strings may be adjusted while running inthe hole.

4. All downhole valves are normally closed while running in the hole.

5. The bypass system in the tools will allow wellbore fluids tocirculate through the tool to avoid being forced into the formation bythe piston effect, if the clearance between the wellbore and the tool isrestricted.

6. The outer string will be slightly underbalanced when compared to thewellbore pressure while RIH to keep the packers fully collapsed andreduce the potential for premature setting when filter cake or tighthole conditions are encountered.

Packer Inflation

1. The packers are inflated by opening the inflation valve and applyingpressure to the outer string until the packer inflation pressure is300-500 psi (2,000-3,500 kPa) above BHP.

2. The inflation valve is then closed, trapping pressure within thepackers. Additional pressure can be added at any time by pressurizingthe outer string and opening the inflation valve.

Evaluation

The most significant aspect of this coiled tubing delivered system isthe flexibility that it provides to the formation evaluation process. Itis expected that all operations to be conducted with this technologywill commence with an evaluation phase, which will normally consist ofat least one flow period and one build up period.

The flow valve, which connects the wellbore to the inner string, isopened electronically to allow produced fluids to flow into the innerstring. The volume of the inner string is approximately 11.5 bbls (1.8m³)

The initial (Preflow) period is usually conducted under closed chamberconditions, providing real time two phase flow rate measurements.Subsequent flow periods may also be conducted under closed chamberconditions when inflow rates are low, or where safety andconfidentiality are of major concern.

Pressure and flow rate data can be monitored continuously in the controlcab at the wellsite, or remotely at the well operators office.

Interpretation

The value of this technology to well operators is encompassed not onlyin the quality of the data that is collected, but more importantly, inthe ability to interpret and utilize that data instantaneously tomaximize operational efficiency.

The essential ingredients for an optimized well test interpretation withthe above described system are:

Two phase-flow rate information on a real time basis.

Sample description and analysis prior to the end of the test.

Reservoir parameters from the well operator. Porosity, net pay, fluidsaturations, etc.

Personnel on location trained in well test interpretation.

Real time pressure build up data sufficient for radial (directionperpendicular to wellbore) (or other flow regime) analysis.

Flexibility to gas lift to maintain reservoir inflow required.

Well test interpretation software package which provides semi-log andlog-log analysis, as well as modeling capabilities and predictions fordamage removed productivity.

A communications system between the field and the well operators headoffice to provide for fast decision making capabilities.

Stimulation/Profile Modification

Treatment fluids will normally be pumped down the inner string withreturns taken either up the outer coil/casing annulus or thecoil-in-coil annulus. The exhaust/intake ports of these conduits arepreferably spaced four and a half feet apart with the inner coil's portjust below the upper packer. This provides the ability to spot thetreatment fluid directly across the majority of the interval beforecommencing squeeze operations.

Produced Fluid Circulation

During the final shut in, or after the packers have been deflated, theproduced fluids within the inner string can be circulated to surface inorder to obtain samples, and to dispose of hydrocarbons and sour fluids.Traditional drill stem testing systems require the use of the wellborefluid for circulating produced fluids from the test string, which raiseswell control concerns and restricts circulation operations until afterthe conclusion of the test. In addition, these systems require that theentire test string be retrieved to surface to reset the circulatingvalve after it has been opened, since the valve cannot be closed.

The coil-in-coil string plus electronic valve control system providesseveral benefits with respect to circulation. The circulating valve canbe opened and closed an unlimited number of times, allowing circulationof produced fluids after each test during multiple test sequenceswithout tripping out the hole. Fluids from the coil-in-coil annulus areused to circulate produced fluids from the inner string, which allowswell control capabilities to be maintained with the wellbore fluid. Theouter coiled fluid will be a clean fluid and will provide a betterinterface to the produced fluids, whereas circulation of wellbore fluidscan result in ambiguity since they are sometimes similar to the producedfluids. Circulation can be accomplished during the final shut in periodof the test rather than utilizing operational time after the conclusionof the test. It also allows samples to be collected and analyzed severalhours sooner.

Packer Deflation

The packers are deflated by opening the inflation valve and allowingpressure to bleed back into the outer string. By using a fluid in theouter string with lower density than the wellbore fluids, the packerscan be returned to a slightly underbalanced state after deflation. Thisreduces the potential for having the tools stuck in the well.

CONCLUSIONS

A new wireline controlled, concentric coiled tubing DST system has beendeveloped for testing, stimulation and profile modification of sourand/or horizontal wells.

The new system has numerous user benefits as outlined above. Namely;safety, sour service rated equipment, circulation control, inflatableelements, multiple sets, test-treat-test and gas lifting capabilities,real-time surface read-out, on-site interpretation and on-line datatransmission to head offices.

The real-time capabilities of the system will result in the optimizationof rig time. The systems flexibility and inherent safety will also allowfor faster turn arounds of these critical operations.

The foregoing disclosure and description of the invention areillustrative and explanatory thereof. Various changes in the size, shapeand materials as well as the details of the illustrated construction maybe made without departing from the spirit of the invention.

The phrase “well operations” as used below in the claims is intended torefer to, and to include, operations such as treating or forming ortesting or measuring and the like, as well as to combinations of theabove operations.

What is claimed is:
 1. Apparatus for use in well operations, comprising:coiled-in-coiled tubing, including an inner coiled tubing length withinan outer coiled tubing length defining a first inner fluid conduit and asecond inner-coil annular fluid conduit; a bottomhole assembly packageadapted to attach to a portion of said tubing such that the assembly isin fluid communication with both said conduits; and at least one packeradapted to be associated with one of said assembly and said tubing. 2.The apparatus of claim 1 wherein said bottomhole package includes atleast one tool selected from the group consisting of a production/testtool, a pump tool, a treatment injection tool, a vacuum tool, a jettingtool, a perfing tool, a drilling tool, an orienting tool, a measurementtool, a hydraulic motor and an electric motor.
 3. The apparatus of claim2 wherein said bottomhole assembly includes a pump selected from thegroup consisting of a jet pump, a chamber list pump and an electricpump.
 4. The apparatus of claim 1 wherein said packer includes astraddle packer.
 5. The apparatus of claim 1 wherein said at least onepacker includes a packer adapted to slidingly attach to thecoiled-in-coiled tubing.
 6. The apparatus of claim 1 wherein said packeris adapted to be associated with said bottomhole assembly.
 7. Theapparatus of claim 1 wherein the bottomhole assembly package includesmeans for testing, treating and retesting.
 8. Apparatus for use in welloperations, comprising: coiled-in-coiled tubing, including an innercoiled tubing length within an outer coiled tubing length defining afirst inner fluid conduit and a second inter-coil annular fluid conduit;and a bottom-hole assembly package adapted to attach to a portion ofsaid tubing such that the assembly is in fluid communication with bothsaid conduits; wherein said bottomhole assembly package includes atleast two tools selected from the group consisting of a drilling tool, aproducing/testing tool, a vacuuming tool, a treatment injection tool, apumping tool, a perfing tool, and orienting tool, an electric motor, ahydraulic motor, a jetting tool and a measuring tool.
 9. The apparatusof claims 1 or 8 including a surface control mechanism for controllingfluid communication within said first and said second conduits.
 10. Theapparatus of claims 1 or 8 wherein the minimum OD of the inner coil is 1inch and the minimum OD of the outer coil is 2 inches.
 11. The apparatusof claims 1 or 8 that includes a wireline extending through one of saidtwo conduits to establish electrical communication between the surfaceand the bottomhole assembly package.
 12. The apparatus of claim 11wherein said wireline comprises at least one conductor within a braidedline.
 13. The apparatus of claim 11 wherein said coiled-in-coiled tubingis coaxial and said wireline is located in said annular conduit.
 14. Theapparatus of claims 1 or 8 that includes means for communicating datafrom said assembly package through said wellbore.
 15. The apparatus ofclaim 14 wherein said bottomhole assembly package includes at least onemeasuring tool connected to said communication means.
 16. The apparatusof claim 15 wherein said measuring tool includes at least one instrumentfrom the group consisting of a temperature measuring instrument, apressure measuring device, a resistively measuring device, a gamma raylogging tool, a sonic logging tool, a neutron logging tool, a loggingtool assembly, a flow meter, a densitometer, a chemical analyzer unit, acasing collar locator, and a downhole fluid measuring and analysis unit.17. The apparatus of claim 14 wherein said communication means comprisescoaxial cable or fiber optic cable.
 18. The apparatus of claim 14wherein the means for communicating data includes means forcommunicating data in real time.
 19. The apparatus of claims 1 or 8wherein said bottomhole assembly package includes a variable spacingunit.
 20. The apparatus of claims 1 or 8 wherein the bottomhole assemblyis adapted to attach to an end portion of said tubing.
 21. The apparatusof claims 1 or 8 that includes a reel/spool and wherein thecoiled-in-coiled tubing is at least partially spooled upon saidreel/spool.
 22. A method for performing well operations, comprising:connecting coiled-in-coiled tubing to a bottomhole assembly package suchthat a first inner fluid conduit and a second inter-coil annular fluidconduit, defined by inner and outer coiled tubing lengths, are in fluidcommunication with said assembly; locating said bottomhole assembly downa wellbore; packing off between a portion of the combination ofcoiled-in-coiled tubing and bottomhole assembly and a portion of thewellbore wall; and communicating fluid through at least one of saidconduits to said assembly package.
 23. The method of claim 22 thatincludes producing wellbore fluid up a conduit.
 24. The method of claim22 that includes circulating fluid down a conduit into the wellbore. 25.The method of claim 24 wherein said circulating fluid down includescirculating a treatment fluid.
 26. The method of claim 22 wherein saidpacking off includes setting a packer using hydraulic fluid circulateddown one of said conduits.
 27. The method of claim 22 wherein saidpacking off includes packing off between said coiled-in-coiled tubingand a portion of said wellbore wall such that the coiled-in-coiledtubing is sealingly, slidingly received through said packer.
 28. Themethod of claim 22 that includes producing wellbore fluids up one ofsaid conduits followed by circulating a treating fluid down one of saidconduits followed by producing wellbore fluids up one of said conduits.29. The method of claim 22 that includes circulating a treating fluiddown one of said conduits followed by producing wellbore fluids up oneof said conduits followed by circulating a treating fluid down one ofsaid conduits.
 30. The method of claim 22 wherein said packing offincludes isolating a portion of said wellbore between a pair of packers.31. The method of claim 30 that includes circulating fluids down oneconduit and up the other conduit to flush out fluids in the isolatedzone.
 32. The method of claim 22 that includes using fluid communicatedthrough one conduit to hydraulically operate a tool attached to thebottomhole assembly package.
 33. A method for performing welloperations, comprising: connecting coiled-in-coiled tubing to abottomhole assembly package such that a first inner fluid conduit and asecond inter-coil annular fluid conduit, defined by inner and outercoiled tubing lengths, are in fluid communication with said assemblypackage; locating said bottomhole assembly down a wellbore; and pumpingfluid down both conduits to at least a portion of said bottomholeassembly, each fluid comprising either a hydraulic operating fluid for atool associated with the assembly package or a well treatment fluid. 34.The method of claim 33 wherein the fluid pumped down each conduitcomprises a different chemical and wherein the chemicals are selected toproduce a chemical reaction when mixed in the wellbore.
 35. The methodof claim 33 wherein said pumping fluid down includes circulating a fluidfrom each one of said conduits to a hydraulically operated tool.
 36. Amethod for performing well operations, comprising: connectingcoiled-in-coiled tubing to a bottomhole assembly package such that afirst inner fluid conduit and a second inter-coil annular fluid conduit,defined by inner and outer coiled tubing lengths, are in fluidcommunication with said assembly package; locating said bottomholeassembly down a wellbore; circulating fluid down one conduit and up theother conduit; and powering a rotating tool downhole with a portion ofsaid circulated fluid.
 37. A method for performing well operations,comprising: connecting coiled-in-coiled tubing to a bottomhole assemblypackage such that a first inner fluid conduit and a second inter-coilannular fluid conduit, defined by inner and outer coiled tubinglanguage, are in fluid communication with said assembly package;locating said bottomhole assembly down a wellbore; communicating a fluidbetween the surface and the borehole through one of said conduits; andmaintaining a thermally insulating fluid in the other of said conduits.38. A method for performing well operations, comprising: connectingcoiled-in-coiled tubing to at least one bottomhole assembly package suchthat a first inner fluid conduit and a second inter-coil annular fluidconduit, defined by inner and outer coiled tubing lengths, are each influid communication with an assembly package; locating at least oneassembly package down a wellbore; and producing fluid up both conduits.39. The method of claims 22, 33, 36, 37 or 38 wherein said locatingincludes injecting said coiled-in-coiled tubing from a reel/spool.
 40. Amethod for assembling coiled-in-coiled tubing, comprising: extending afirst length of coiled tubing upon the surface; and inserting by meansof a coiled tubing injector a second length of coiled tubing throughsaid first coiled tubing.
 41. A method for assembling coiled-in-coiledtubing, comprising: extending a first length of coiled tubing upon thesurface; and pulling a second coiled tubing length through said firstcoiled tubing length by means of a cable inserted through said firstcoiled tubing.
 42. The method for assembling coiled-in-coiled tubingcomprising: extending a first length of coiled tubing upon the surface;and pumping a second coiled tubing length through the first coiledtubing length.
 43. The method of claims 40, 41 or 42 that includeslubricating between the second and the first coiled tubing lengths. 44.Apparatus for use in well operations, comprising: coiled-in-coiledtubing, including an inner coiled tubing length within an outer coiledtubing length defining a first inner fluid conduit and a secondinter-coil annular fluid conduit; and a bottomhole assembly packageadapted to attach to a portion of said tubing such that the assembly isin fluid communication with both said conduits; wherein said bottomholeassembly package includes means for testing, treating and retesting.